Separation of water from hydrocarbons

ABSTRACT

A method for the removal of dissolved water or water and ice from hydrocarbon liquids such as petroleum refinery fuels or natural gas liquids in a manner which enables the fuels to be readily treated by the coalescence/separation technique while reducing the potential for plugging filters and other equipment with ice crystals. Free water or water/ice is removed from the liquid hydrocarbons by contacting the hydrocarbon feed with a treating agent which as an affinity for water prior to subjecting the mixture to coalescence/separation. The treating agent is preferably a co-solvent for the water and the hydrocarbon such as an alcohol e.g. methanol. The treating agent and water are separated from the hydrocarbon component during the coalescence/separation and recirculated to the feed with the composition of the recycle aqueous phase being controlled to achieve the desired level of water removal to meet relevant product specifications. Consistent with the removal of the water during the coalescence/separation, the water concentration of the recycle loop containing the co-solvent/water blend gradually increases with removal of the water from the feed. This progressive increase in water level can be compensated by controlled addition of pure co-solvent to the recycle coupled with continuous or periodic dumping of excess mixture. Alternatively, the circulating mixture may be subjected to continuous or batch regeneration or disposed of in any other way which is convenient and economical.

CROSS REFERENCE TO RELATED APPLICATION

This application relates to and claim priority to U.S. ProvisionalPatent Application No. 60/996,602 filed on Nov. 27, 2007.

FIELD OF THE INVENTION

This invention relates to a method for the separation of water fromhydrocarbons, especially liquid hydrocarbons such as petroleum naphthas,natural gas condensates, petroleum fuels such as gasoline, middledistillates such as road diesel fuel and kerojet, particularly under lowtemperature conditions. The water removed may be present as such in thehydrocarbons or mixed with other water-miscible materials orcontaminants which may be removed simultaneously with the water.

BACKGROUND OF THE INVENTION

Significant amounts of water become mixed with hydrocarbon streamsduring production and processing. Petroleum refinery streams, forexample, may be treated with water, steam or various aqueous solutionsduring processing in order to carry out the processing and to meetvarious quality specifications. Steam stripping, caustic treating andamine treating are frequently used in conventional refinery processingand although much of the water introduced in this way can be removed bysimple settling procedures, a certain amount of water remains in thefuel after removal of the bulk of the water. Excess amounts of waterfrequently adversely affect the properties and quality of hydrocarbonfuels, for example, by creating haze in fuels which would otherwise beclear, accelerating rust and other forms of corrosion on containers andequipment, and by the formation of ice crystals at low temperatureswhich may lead to plugging of filters and other equipment, for example,fuel injectors. Water may also contain contaminants such as acids whichmay lead to accelerated corrosion. It is therefore usually necessary toseparate any remaining water from petroleum fuels and other products inorder to meet various product specifications; the separation may becarried out out at the refinery, at the distribution terminal or at thelocation of use, for example, the airport.

Product specifications frequently require relatively low levels of waterin order to avoid the problems mentioned above, for example, ASTM D 2709for diesel fuel oils sets a 0.5% volume maximum limit on water insediment for diesel fuel oils varying from light distillate fuels forroad diesels (1D fuel) up to heavy distillate fuels (4D fuel) for lowand medium speed diesels operating at constant speed and load. Similarspecifications may be found for other hydrocarbon fuels including motorgasoline and middle distillate products including home heating oil,aviation kerosene and vaporizing oil. Products sold in cold climates areparticularly subject to problems arising from the freezing of water andthe consequence formation of ice crystals at temperatures belowfreezing, the problems of product quality control are thereforeexacerbated in such climates.

The production of petroleum hydrocarbons from subterranean formationsmay also result in hydrocarbon streams which are contaminated by water,either alone or mixed with other contaminants. While water, e.g. brine,may normally be readily separated from liquid crudes, problems may beencountered with the separation of water from other produced fluids, forexample, natural gas condensates which are relatively light, low boilinghydrocarbon fractions produced from natural gas wells. One instance ofthis problem is in the production of natural gas which has a relativelyhigh water content which leads to undesirable hydrate formation;hydrates normally require removal prior to the shipping of the gasbecause of their propensity to plug equipment and flowlines. Waterremoval may usually be effected by the addition of a dehydrating agentor hydrate suppressor such as ethylene glycol followed by separation ofthe water/glycol phase from the hydrocarbon liquids in the conventionalmanner. Large quantities of water which are encountered in some gasfields, especially when low ambient temperatures are prevalent, mayhowever make normal processing techniques ineffective or of limitedutility. An effective method of water separation would therefore beuseful for applications such as this.

While chemical methods may be used to remove water from the main body ofthe fuel, they have generally received less commercial acceptance on thelarge scale used in refinery operations because of the cost factor.Chemical methods, including salt drying, require the replacement orregeneration of the reagents used in the process and the reagentsthemselves and their products formed by interaction with the waterfrequently introduce their own complications in subsequent processing.Because the cost of the reagents is directly proportional to the amountof water in the product, physical methods of separation have normallybeen preferred since their operational cost is not so directly relatedto the amount of water which needs to be separated.

Various physical separations have been used including centrifugalseparation and filtration, for example, using sand filters. A techniquewhich has, however, become commercially attractive in recent years isliquid/liquid coalescence. See, for example, Refining Details Advancesin Liquid/Liquid Coalescing Technology, Gardner, Today's Refinery, March1997. The method of coalescing a liquid suspended in another immisciblephase using a coalescing device frequently referred to as a coalescer,has been found useful for removing liquids both from the gaseous phaseas in aerosols and from suspensions of one liquid in another liquid withwhich it is immiscible but may be soluble to a limited degree.Coalescing devices are particularly effective where the volume of liquidto be removed is small in comparison to the volume of the phase fromwhich it is removed so that the technique is of potential applicationfor the separation of small quantities of water from hydrocarbon fuels.The Gardener article discusses the factors that are relevant to thecoalescence of droplets of the discontinuous phase from the continuousphase and the ease or difficulty of separation of the immiscible phases.These factors include the physical properties of the phases such asdensity, viscosity, surface tension and interfacial tension. Inaddition, the properties of the system such as drop size, curvature ofthe liquid/liquid interface, temperature, concentration gradients andvibrations may also affect the effectiveness of the coalescence. Asnoted in U.S. Pat. No. 5,443,724 (Williamson) any or all of thesefactors may be significant in a particular situation but the density,drop size and interfacial tension of the two liquids appear to be themost significant factors as well as those over the least amount ofcontrol can be exercised in affecting the separations.

The type of coalescer employed for the separation depends on thedifficulty of separation or coalescence as influenced by the variousrelevant factors outlined above. The type of fluids being separatedfrequently determines the nature of the packing used in the coalescencedevice. Glass fibers have found widespread industrial application incommercial devices. Frequently, however, the presence of surfactants inwater/hydrocarbon emulsions lowers the interfacial tension to a valueless than about 20 dynes/cm at which the emulsions are stable enough toresist being broken through processing in conventional meshpacking/glass fiber coalescers as well as by other techniques. Whileelectrostatic precipitators may be effective on such emulsions down tointerfacial tensions below 10 dyne/cm, their use is rather less favoredthan the relatively cheaper coalescence method. Surfactants disarmconventional glass filters coalescers by bonding with glass fibers,allowing water molecules to flow through the coalescers with thehydrocarbons. Frequent changes of the cartridge material in thecoalescers may obviate this problem but the increased labor and disposalcosts associated with frequent cartridge change out are undesirable asis the continued need to monitor the quality of the product to ensurethat appropriate specifications are being met. The use of variouspolymeric materials such as phenolic or acrylic resins which actprimarily as binding agents for glass fiber packings may be effective toreduce disarming of coalescers to a significant extent, but the problemremains.

U.S. Pat. No. 5,443,724 discloses a coalescer-separator apparatus whichenables longer coalescer cartridge life to be obtained as a result ofimproved flow distribution within the device. The device is stated to beparticularly suitable for the separation of water from organic liquidssuch as fuels and is capable of achieving extended life using a morecompact unit with the same or improved level of performance compared tolarger conventional units. As described in U.S. Pat. No. 5,443,724, thecoalescence is carried out using a packing material which has a criticalwetting surface energy which is intermediately critical wetting surfacetension (CWST) of the discontinuous and continuous phase liquids. Thisresults in the formation of droplets of the discontinuous phase, afterwhich the mixture of the continuous phase liquid and the droplets of thediscontinuous liquid are conducted to a separating element which permitsthe continuous phase liquid (petroleum fuel) to pass but substantiallyresist or prevent passage of the discontinuous phase which can then beseparately collected and taken away from the bulk of the product.

Various porous media with differing surface energies are mentioned inU.S. Pat. No. 5,443,724 including polytetrafluoroethylene (PTFE),polybutyleneteraphalate (PBT) and other polyfluorinated polymers such asfluorinated ethylene and propylene (FEP) resins. These materials whichprovide the requisite surface energy to the coalescence/separationfilters may be used in the form of a coating of a backing such as glassfiber, stainless steel screens or pleated paper packs. Other mediasuitable for use as the functional or discontinuous phase barriermaterial of the separating element are disclosed, for example, in U.S.Pat. No. 4,716,074 (Hurley) and U.S. Pat. No. 4,759,782 (Miller);reference is made to these patents for details of suitable materials forproviding the requisite surface properties in coalescence/separationdevices.

Normally, separation of liquids by the coalescence technique requiresthree stages to be successful. First of all, filtration is required toremove fine particles such as iron oxide and iron sulfide that stabilizeemulsions and for this purpose, mesh, screen, packed and sand filtersare normally satisfactory. Filtration is followed by the coalescencestep which, in the case of water and hydrocarbon fuels, is normallyaccomplished by the use of fluoropolymer membranes which are effectiveemulsion breakers in liquids with an interfacial tension of greater thanabout 1 dyne/cm. Separation takes place when the coalesced waterdroplets are repelled by a hydrophobic barrier membrane, again normallyformed from a polymeric material such as fluoropolymer, which permitsthe hydrocarbon fuel to flow through the cartridge while preventingtransfer of the water across the membrane.

Regardless of the details of the coalescence/separation techniques usedone problem that remains, particularly in cold climates, is the problemof icing. When the fuel which is to be treated contains relatively highlevels of water, low temperatures cause the water to freeze and form icecrystals which plug filters, including the prefilters used incoalescence/separation. Accordingly, regardless of the potential forutilizing the coalescence/separation technique, problems arising fromthe presence of water in the feed still remain.

SUMMARY OF THE INVENTION

A method has been devised for the removal of dissolved water or waterand ice from hydrocarbon liquid products in a manner which enables thehydrocarbon products to be readily treated by the coalescence/separationtechnique while reducing the potential for plugging filters and otherequipment with ice crystals or solid deposits. According to the presentinvention, dissolved water or water/ice is removed from liquidhydrocarbons by contacting the a feed stream of the hydrocarbon with aliquid treating agent having an affinity for water prior to subjectingthe hydrocarbon/treating agent mixture to coalescence/separation toremove the water from the hydrocarbon. The treating agent is separated,together with water removed from the feed stream, from the hydrocarbonproduct by the coalescence/separation step and recirculated to the feed.The composition of the circulating aqueous phase comprising the treatingagent and removed water is controlled to achieve the desired level ofwater removal to meet relevant product specifications. Consistent withthe removal of the water during the coalescence/separation, the waterconcentration of the circulating treating agent/water blend will tend toincrease gradually with transfer of the water in the feed to thecirculating fluid. This progressive increase in water content can becompensated by controlled addition of pure treating agent solvent to therecirculating fluid coupled with accumulation of the treatingagent/water mixture and continuous or periodic dumping of excessmixture. Alternatively, the circulating mixture may be subjected tocontinuous or batch regeneration or disposed of in any other way whichis convenient and economical. The treating agent which finds a widedegree of utility as well as being economically favorable comprises amixture of (i) water with (ii) a water-hydrocarbon co-solvent. Thepreferred class of co-solvents are the alcohols, especially methanol,but other water-miscible organic compounds may also be used, asdescribed below. Other, generally less favorable treating agents whichmay be used include strong aqueous salt solutions, as well as organicand inorganic liquids such as amines or even acids, particularly if itis desired to remove a contaminant from the hydrocarbon which can bereacted with the treating agent or a component of it.

DRAWINGS

The single FIGURE of the accompanying drawings is a schematic flowchartof a system for removing water from hydrocarbon liquid products using acoalescence/separation technique.

DETAILED DESCRIPTION

The present invention is applicable to the separation of water, eitheralone or mixed with other contaminants, from hydrocarbon liquids. Themethod is particularly applicable to the separation of water from lighthydrocarbon liquids of relatively low viscosity, comparable to that ofthe water to be separated. The method is of particular applicability tothe separation of water from refinery hydrocarbon fuels includinggasoline (including heavy gasoline and light gasoline), middledistillates such as home heating oil, vaporizing oil, road dieselincluding all ASTM D2 diesels, kerosene type aviation fuels, as well aspotentially to other liquid hydrocarbon product streams which requireremoval of water in order to meet product specifications or otherservice or commercial requirements. Normally, the amount of water whichis present in these materials prior to separation will be relativelysmall, typically not more than about 5 volume percent, but productspecifications will normally require a much lower water content in orderto be acceptable. For example, as noted above, D2 diesel fuel isrequired to contain no more than 0.2% combined water and sediment andsimilar requirements will be encountered with aviation kerosenes in viewof the very low temperatures encountered by military and commercial jetaircraft at high altitudes. The present separation technique is notdependent upon the chemical composition of the hydrocarbon fuel exceptto the extent that the chemical composition affects physical propertiessuch as specific gravity, interfacial surface tension, miscibility withwater and viscosity. The chemical composition may also affect the degreeto which surfactants added during processing or spontaneously formedduring the processing (for example, during caustic washing) and theeffect the surfactants may have on the other properties, especiallyemulsion stability, micelle formation, reverse micelle formation.

The present method is also applicable to the separation of water fromnatural gas liquids also known as natural as condensates. These lowviscosity hydrocarbon liquids generally comprise propane, butane andpossibly higher hydrocarbons separated from the lower boiling methaneand ethane in natural gas from subterranean wells. Natural gas may, asnoted above, need to be treated at or near the wellhead to remove eitherproduced water or water combined with various chemicals such as hydratesuppressors, for instance, ethylene glycol, which have been used totreat the produced gas and which have separated out with the liquids asa result of their boiling in the temperature range set for the liquids.Thus, the present invention provides an effective method for the removalof water/glycol (ethylene glycol) mixtures from natural gas liquids.

In the present method, a liquid treating agent which has an affinity forthe water in the hydrocarbon feed is mixed with the liquid hydrocarbonbefore the fuel is subjected to coalescence/separation treatment. Thetreating agent causes the water and possibly other contaminants to forman aqueous mixture which, when in fully coalesced form, is substantiallyimmiscible with the hydrocarbon although initially it may be suspendedin the majority hydrocarbon phase and not readily separable from it byother means. It is this aqueous mixture which is then separated from thehydrocarbon in the coalescence/separation step. During thecoalescence/separation treatment, the treating agent and water areseparated in the form of a single coalesced phase which is substantiallyimmiscible with the hydrocarbon majority component and recirculated forfurther addition to the feed. An illustrative schematic of the processconfiguration is shown in the attached FIGURE by way of example.

The treating agent has for its required effect to have an affinity forthe water which is to be removed from the hydrocarbon feed. It may alsodesirably have an affinity for any other contaminants in the feed whichshould be removed at this time. For example, if the feed also containsan acidic contaminant such as hydrogen sulfide, the use of an amine asthe treating agent may be used to effect removal of the hydrogen sulfideas well as of the water. Conversely, if the feed is, for example, arefinery stream containing basic contaminants such as alkalis fromcaustic treatment, the use of an acidic treating agent may be effectiveto remove both water and the residual alkali. The reactive components ofthe treating agent may make up the entire treating agent or may be addedas additive components.

As described in greater detail below, a very useful treating agent is amixture of water and a co-solvent, miscible with both the alcohol andwith the hydrocarbon. This has been found to be very effective inremoving water from refinery liquid fuel products such as gasoline andmiddle distillates such as road diesel, kerojet or heating oil. As notedbelow, it may also be used with natural gas condensates. One preferredembodiment of the invention is shown in the drawing and is describedbelow by reference to the treatment of a refinery fuel with such atreating agent.

In the FIGURE, a refinery fuel such as mogas, road diesel or kerojet isintroduced by way of line 11 to prefilter 12 with the alcohol/watermixture being added through line 13. Prefilter 12 is suitably a mesh orscreen filter with additional packing, e.g. compressed glass fibers orpolymer (nylon, polyolefin) mesh, adapted to remove fine particulatematter such as iron oxide, silica, which may stabilize emulsions andpossibly damage the coalescer/separation units. Use of a high efficiencyprefilter such as a sand filter may result in some removal of water.

After passing through prefilter 12, the blend of hydrocarbon, alcoholand water passes through line 14 to coalescence/separation unit 15.Coalescer unit 15 is divided into two stages, comprising a first orcoalescence stage 16 and a second or separation stage 17. In thecoalescence stage, the suspended particles of water are subjected tocoalescence into larger droplets in the presence of a suitablecoalescing medium through which the liquids pass in order to effect thedesired coalescence of the water, now with the added co-solvent. Inseparation stage 17, the combined fluids pass over a separation membranewhich is selected to have a surface energy favoring passage of thehydrocarbon phase through the walls of the separation membrane whileexcluding the aqueous phase comprising the co-solvent and the water. Theliquid hydrocarbon fuel, now containing only a small and acceptableamount of water passes out of the coalescence/separation unit throughline 18 to product storage while the separated co-solvent/water phase,now containing water removed from the original fuel feed, is removedthrough line 19 for recirculation to the feed. A control valve 20 isprovided in the recycle loop under control of manual or automaticcontroller 21 to permit actuation of the recycle when required.Recirculation is generally not required for operation above freezingpoint (0° C.) when only the normal coalescence of free water isrequired, with no hazard of ice crystal formation. When seasonal ambienttemperatures drop below freezing, however, and icing and filter pluggingare prevalent, injection and recirculation of the co-solvent/water blendcan be initiated in order to prevent filter and equipment plugging byice crystals. Actuation of the injection of the co-solvent/water blendinto the feed and recirculation can be initiated either manually orautomatically in response to ambient temperature sensors or, preferably,by a pressure sensor on a filter responsive to pressure increase uponplugging with ice crystals.

The alcohol/water blend passes from control valve 20 to injection line13 through line 22 with additional co-solvent being injected to thecircuit through line 24 in order maintain the desired co-solvent/waterratio for effective coalescence and separation. As water isprogressively removed from the fuel feed, and makeup co-solvent isadded, excess co-solvent/water mixture may be purged through the circuitthrough line 25 and to dump tank 26 from which the blend may be removedthrough line 27. While it is acceptable to allow an accumulation ofwater in the recirculation loop up to a permitted maximum set byprocessing requirements (permissible water concentration in fuel,acceptable co-solvent loss to fuel), it will normally be preferred tomaintain the loop at a constant composition ratio between the co-solventand the water by periodic or continuous addition of co-solventaccompanied by removal of excess circulating liquid. Removal of theexcess co-solvent/water may be carried out continuously or periodicallyor, as an alternative, the gross composition of the recycle loop may becontrolled by removal of the water from the co-solvent, for example bydistillation, or reverse osmosis to the extent required to maintainconstant composition in the recycle loop. Reclamation of the co-solventin this way is potentially attractive since the regenerated co-solventis recycled to the process while removing trace contaminants such assalt or trace soaps/surfactants arising from the processing. As analternative, the co-solvent/water may, depending on the nature of theco-solvent, be disposed of as a relatively clean combustible mixture.With methanol as the co-solvent, for example, the methanol/water blendmay be used as a low energy content fuel in certain burner andindustrial processes, especially if the energy content is maintainedabove about 18,000 kJ/kg. The exact choice of method by which thecomposition of the recycle stream is maintained at the desired value isnot, however, important and may be selected according to convenience,local economics and other considerations.

The same technique may be used to separate water/glycol mixtures fromnatural gas condensates. In this case, similar considerations applyexcept that the residual water content in the gas may not be as low asrequired for high quality fuel products, being set, however, bypipelining specifications which may vary according to the temperatureconditions prevailing along the pipeline with more stringentspecifications prevailing in the colder climates and for underseapipelines.

The co-solvent which is used in the blend with the water to promoteremoval of the water from the hydrocarbon feed is a liquid which ismiscible with both water and the hydrocarbon majority component, atleast to a limited extent. Organic liquids such as oxygenates aregenerally suitable and preferred for this purpose in view of theiravailability, cost and functioning in the present process. Whileoxygenate esters such as the esters of lower fatty acids and loweralcohols such as ethyl acetate, ethyl propionate, propyl acetate, ethylbutyrate, amyl acetate, esters of the lower alkanols such as methanol,ethanol, propanol and the lower oxo-alcohols with lower fatty acids suchas hexanoic acid, octanoic acid (e.g. 2-ethyl hexanoic acid), as well asother oxygenates such as the ketones, such as acetone, methyl ethylketone (MEK), methyl propyl ketone, aldehydes, ethers such as dimethylether and methyl propyl ether, may be used, the preferred co-solventsare alcohols, especially the lower alkanols such as methanol, ethanoland propanol. Alcohols are particularly suited to the removal ofwater/glycol mixtures from natural gas condensates in view of theirmiscibility for with both the water and the glycol hydrate suppressor.

The extent to which the co-solvent is required to be miscible with bothwater and the hydrocarbon is not important as long as the selectedco-solvent is miscible with water in all proportions which are used inthe process and that the co-solvent has an affinity for water. It is theco-solvent's affinity for water which effects the dehydration of thehydrocarbon e.g. the fuel or NGL (natural gas liquids) and itsmiscibility with the water which enables the blend of co-solvent andwater to be effectively removed from the hydrocarbon by the coalescencetechnique. The extent to which the co-solvent may be miscible with thehydrocarbon may affect the extent to which the dehydration is completed,a factor which may be significant with fuels. It may also affect thelosses of the co-solvent to the hydrocarbon (see below). In order tomaintain the loss of co-solvent to the hydrocarbon within acceptablelimits a limited miscibility of the co-solvent/water mixture with thehydrocarbon is desirable. For this reason, blends of methanol with waterparticularly commend themselves since blends of these components withhigh water contents are almost insoluble with hydrocarbon fuelsincluding gasoline as well as NGL.

The lower alkanols which from the preferred class of co-solvents for usein the present process are those which have a limited solubility inliquid refinery hydrocarbon fuels and NGL. Since the compositions offuel and NGL may vary, the selected alcohol may vary also. As with otherpotential co-solvents, the alcohols will be selected for their mutualsolubility in hydrocarbons and water as well as their convenientavailability and favorable economics. The alcohols may be monohydric,dihydric or higher alcohols although monohydric and dihydric alcohols(glycols) will normally be preferred. Other functional groups may alsobe present on the alcohols, for example, ether groups, although halogenswill normally not be preferred for reasons of cost, toxicity, andcorrosion potential; hydroxyamines should normally be excluded in viewof their potential to act as surfactants for the hydrocarbon/watersystem. The preferred monohydric alcohols are methanol and ethanolalthough propanol may also be used to advantage and glycols such asethyleneglycol, propyleneglycol, dipropyleneglycol, as well as glycolethers such as ethyleneglycol methylether, diethyleneglycol methyletherand others will be found suitable. Alcohols with relatively highersolubilities in the hydrocarbon phase may be used at the expense ofexcessive losses to treated fuels and NGL unless they are combined withrelatively high amounts of water, a measure which detracts from thedehydration which is the object of the process. The loss of alcohol orother selected co-solvent to the fuel is not, however, in it selfnecessarily undesirable since the alcohol may act as a deicer in thefuel product, both during distribution and subsequent use, soeliminating the need for a separate deicing additive injection.

As noted above, however, it is possible and on occasion may be desirableto use alternative treating agents. In order to remove water fromhydrocarbon products it is possible, for example, to envisage the use ofstrong aqueous salt solutions. These have the required affinity forwater as a result of their high concentration of mineral salt and, as aresult of the removal of the water from the hydrocarbon feed, wouldbecome progressively more dilute until their effectiveness ceases. Bycontrol of the composition of the circulating fluid stream, e.g. by theaddition of more salt and withdrawal of excess volume, it is possible toutilize these salt solutions in the same way as the alcohol/watermixtures referred to above. Sodium chloride solutions will not be foundto be optimal in this application but strong solutions of other saltssuch as calcium chloride or sodium sulfate will be more effective. Theuse of strong solutions may be found very effective in warmer climateswhere freezing problems will not be encountered. The use of saltsolutions may also be economically favorable. The same simpleconventional methods may be used to maintain the concentration of thesalt in the solution to restore its functionality as the dehydratingagent, e.g. by the addition of fresh salt and removal of a portion ofthe circulating volume of liquid or by regenerating the solution, forexample, by distillation or membrane separation (osmosis).Alternatively, salt solutions may be cheap enough to be used on aonce-through basis with regeneration, particularly if used onlyintermittently.

Other materials which have an affinity for water may be used as thetreating agent. Liquid amines in particular, commend themselves for thispurpose, especially when acidic contaminants such as hydrogen sulfideare to be removed from the hydrocarbon. Amines may be as technicallypure compounds or as solutions in water as long as the required affinityfor water is retained. Suitable amines for this purpose many includesubstituted amines such as triethanolamine and diethanolamine as well assimple amines such as monoethanolamine. These treating agents may beuseful for removing water simultaneously with acidic contaminants suchas hydrogen sulfide or carbonyl sulfide from natural gas liquids.

The amount of the treating agent, e.g. co-solvent/water blend which isadded relative to the feed and the relative amounts of co-solvent andwater in the blend are codependent variables to a certain extent. Asnoted above, a loss of the co-solvent to the hydrocarbon does take placebut this can be controlled by increasing the amount of water in theblend which is injected into the fuel. On the other hand, the additionof more water detracts from the effectiveness of the dehydration ifresort is made to this expedient in order to limit the loss ofco-solvent to the fuel. Another factor which requires consideration isthe effect of the co-solvent upon the fuel product specifications. Largeamounts of the lower alcohols such as methanol and ethanol or othervolatile co-solvents, may degrade flash point of treated fuels to anextent that fuel product specifications are not met. Thus, increasingthe relative amount of water in the mixture may be effective forcontrolling changes in flash point during the treatment process althoughpossibly at the expense of diminished effectiveness for water removal.The higher alcohols such as dipropyleneglycol may, however, may be addedto distillate fuels after the water removal process to act as high flashpoint deicers during subsequent distribution and use. In general,however, the loss of co-solvent to natural gas liquids will representmerely an economic loss of the process rather than having a major effecton the product (NGL) quality.

The amount of water in the co-solvent/water blend will depend upon theselected co-solvent, its solubility in the hydrocarbon components of thefuel or other hydrocarbon liquid, the ratio of water/co-solvent blend tothe hydrocarbon, operating temperature and other factors. Taking thelower alcohol, methanol, as the selected solvent, the ratio of methanolto water will normally vary between 20/80 and 80/20 by volume. Thisratio will vary with other alcohols and other co-solvents according tothe specific alcohol or other co-solvent selected, its solubilitycharacteristics with water and the hydrocarbon and the extent to whichtransfer of the alcohol to the hydrocarbon fuel can be tolerated and theamount of water in the initial hydrocarbon feed. Normally, however, withmethanol as the alcohol, the volume ratio of alcohol and water will befrom about 75:25 to 25:75 with approximately 50:50 blends being normallyadequate.

The preferred alcohol for use in the present process is methanol whichis selected not only for its low cost, low viscosity and boiling point(if reclaiming is desired) but also for its effectiveness in dissolvingsolid ice when present. A 50:50 methanol/water blend has been found tobe extremely effective and this ratio is sufficiently concentrated todehydrate the fuel down to low water levels. The freezing point of a50/50 methanol/water mixture is below 40° C. so the process is capableof operating at ambient temperature over wide limits from less than −40°C. up to relatively high ambient temperatures. This reperesents a veryuseful working range, especially for use with fuel treatment in coldclimates and for gas condensate treatment when low temperature gaspipeline specifications have to be met. Methanol has the additionaladvantage that loss to the hydrocarbon fuel majority component isrelatively small, as compared to higher alcohols and for this reason,process losses may be minimized. Combinations of alcohols such asmethanol with dipropyleneglycol may be used when it is desired toachieve some losses to fuels in order to provide residual deicingcapability for the treated fuel product.

The amount of the co-solvent/water blend which is added to thehydrocarbon feed is typically less than 10% by volume of the total feedalthough the exact amount selected will be depend upon the degree ofdehydration desired, the co-solvent e.g. alcohol selected, the ratio ofwater to co-solvent in the blend and any relevant product specificationssuch as flash point for treated fuel products. Also relevant would bethe ratio of water and glycol in treating natural gas condensates whichhave been treated with glycol hydrate suppressor. Normally, in the caseof alcohol/water blends, the amount of the alcohol/water blend will befrom 0.1 to 10% by volume of the total fuel feed and in most cases from0.5 to 5% of the feed will be found sufficient. In many cases, about 1%by volume of the feed will be adequate with the 50/50 methanol/waterblend selected for the dehydration.

The prefilters which are used ahead of the coalescer may be any suitabletype of conventional filter, including sand filters, metal or polymermeshes, or other porous material capable of removing small solidparticles which would tend to stabilize the fuel/water emulsions andwhich might result in damage to the more delicate coalescer membranes.Polyester and nylon mesh filters are suitable, typically with crushstrengths in the range of 70-145 kg.cm⁻² (75-150 psi) and othernon-woven filter materials may be used as convenient alternatives. Thefilter material may be contained in a conventional filter housing andthe filter material in any convenient configuration which provides thedesired filter life, filtration capacity and flow rate, for example,pleated mats, cylindrical sheets or mats, helical or spirally woundmats.

In a similar manner, the material of the coalescer and separationelements in the coalescing unit and the separation unit may be providedin a form which provides the necessary mechanical strength, liquid flowrate and unit life. In the simplest form, the media serving as thecoalescer and separator materials may be provided in sheet form whichmay be formed either as flat sheets, pleated or corrugated sheets or inother suitable arrangements e.g. cylindrically, helically or spirallywound sheets, as disclosed in U.S. Pat. No. 5,443,724 to which referenceis made for a disclosure of suitable coalescer and separator materialsand configurations for them.

The coalescer promotes the coalescence of the discontinuous or highlydivided phase of the hydrocarbon/water mixture in which the water is inthe form of finely divided droplets which are immiscible with thehydrocarbon phase into larger and coarser droplets. The coalescingmaterial is used in the form of a packing in which the material has acritical wetting surface energy intermediate the surface tensions of theliquids forming the continuous and discontinuous phases, that is, of thehydrocarbon majority component and the water which is to be removed. Inpractice, this means that the medium needs a surface energy of less thanabout 72 dynes/cm. Similarly, the material of the separating element isselected so as to have a surface energy which permits passage of themajority hydrocarbon component through the small pores of the separatormaterial but to preclude transfer of the water across the wall. In thiscase, since water is the discontinuous phase which is to be separated(along with the alcohol/water injected) the separator materials areselected to have a critical surface energy (CWST) below the surfacetension of water which is typically about 72 mN·m⁻¹. As disclosed inU.S. Pat. No. 5,443,724, materials preferred for use as the phasebarrier material for the separator include silicones, such as siliconetreated paper and more preferably fluoropolymeric materials of whichfluorocarbons or perfluorocarbons (perfluoro resins) are particularlypreferred. Examples of preferred materials for use as the packing orcoating in the separator include polytetrafluoroethylene (PTFE) or otherpolyfluorinated polymers such as fluorinated ethylenepropylene (FEP)resins. As noted, a preferred separator material includes a coating ofone of these materials on a stainless steel screen or a pleated paperpack. Other suitable materials include those disclosed in U.S. Pat. No.4,759,782 to which reference is made for a disclosure of such materials.Generally, the phase barrier material which acts to prevent thediscontinuous phase passing through it (and is therefore appropriatelyreferred to as the discontinuous phase barrier material) is selected tohave pores smaller than a substantial amount of the droplets of theliquid which forms the discontinuous phase. Typically, the pore size ofthe functional part of the separator material is selected to be from 5to 140 microns, preferably 40 to 100 microns. When, as in this case, thediscontinuous phase is water, the pore size is preferably approximately80 microns.

The coalescing unit and the separation unit may suitably be contained ina housing which provides and adequate number of coalescing/separatingelements with these elements being suitably arranged inside the housingfor reasons of functionality and operating convenience. A suitablearrangement is shown in U.S. Pat. No. 5,443,724, using coalescer andseparator cartridge elements arranged in super posed relationship withone another in a cylindrical type housing which permits ready access tothe cartridges when they require replacement. However, otherconfigurations may be used and reference is made to commercial suppliersof this equipment including Pall Corporation of East Hills, N.Y. 11548.

1. A method for removing water or water and ice from a liquid hydrocarbon, which comprises: contacting the a feed stream of the hydrocarbon with a treating agent having an affinity for water which is immiscible with the hydrocarbon, subjecting the mixture of hydrocarbon and treating agent to coalescence/separation to coalesce the non-hydrocarbon components of the hydrocarbon/water/treating agent mixture to form larger size coalesced liquid droplets, separating the coalesced liquid droplets comprising water and treating agent from the hydrocarbon to form a dehydrated hydrocarbon product, recirculating water and treating agent separated from the hydrocarbon as a recycle blend to the feed stream of the hydrocarbon.
 2. A method according to claim 1 in which the treating agent comprises a mixture of water and a co-solvent for water and the fuel
 3. A method according to claim 2 in which the co-solvent comprises an alcohol.
 4. A method according to claim 3 in which the alcohol comprises a lower monohydric alcohol or a lower dihydric alcohol.
 5. A method according to claim 3 in which the alcohol comprises methanol, ethanol, propanol, ethyleneglycol, propyleneglycol or dipropyleneglycol.
 6. A method according to claim 4 in which the alcohol comprises methanol.
 7. A method according to claim 1 in which the mixture of hydrocarbon feed and the blend of treating agent and water is separated by a three stage separation sequence comprising filtration, coalescence of water and treating agent into droplets and separation of the coalesced liquid droplets.
 8. A method according to claim 2 in which the volume ratio of the co-solvent/water blend to the hydrocarbon feed is from 0.1 to 10 volume percent.
 9. A method to claim 2 in which the volume ratio of the co-solvent to the water in the blend which is mixed with the hydrocarbon feed is from 80:20 to 20:80 co-solvent:water.
 10. A method according to claim 9 in which the volume ratio of the co-solvent to the water in the blend which is mixed with the hydrocarbon is from 60:40 to 40:60 co-solvent component: water.
 11. A method according to claim 1 in which the water concentration of the recirculating treating agent/water blend gradually increases with removal of the water from the feed.
 12. A method according to claim 1 in which the composition of the recycle blend is controlled to achieve the requisite level of water removal for the hydrocarbon product to meet relevant product specifications.
 13. A method according to claim 12 in which the composition of the recycle blend is controlled by addition of treating agent to the recycle blend.
 14. A method according to claim 13 in which a portion of the recycle blend is removed from the recirculation.
 15. A method according to claim 1 in which the mixing of the treating agent and water blend with the hydrocarbon feed is initiated by automatic control responsive to an indication of ice crystal accumulation in the hydrocarbon.
 16. A method according to claim 1 in which the hydrocarbon comprises a petroleum refinery liquid fuel product.
 17. A method according to claim 16 in which the fuel product comprises a gasoline or middle distillate fuel product.
 18. A method according to claim 17 in which the middle distillate fuel product comprises a road diesel fuel.
 19. A method according to claim 1 in which the hydrocarbon comprises natural gas liquids.
 20. A method according to claim 19 in which the natural gas liquid feed comprises natural gas liquids, water and glycol and in which the glycol is separated from the natural gas liquids with the water. 